A Table of References is provided herein, immediately preceding the claims. All REF. numbers referred to herein are identified in the Table of References.
Oil shales, source rocks, and other organic-rich rocks contain kerogen, a solid hydrocarbon precursor that will convert to producible oil and gas upon heating. Production of oil and gas from kerogen-containing rocks presents two primary problems. First, the solid kerogen must be converted to oil and gas that will flow through the rock. When kerogen is heated, it undergoes pyrolysis, chemical reactions that break bonds and form smaller molecules like oil and gas. The second problem with producing hydrocarbons from oil shales and other organic-rich rocks is that these rocks typically have very low permeability. By heating the rock and transforming the kerogen to oil and gas, the permeability is increased.
Several technologies have been proposed for attempting to produce oil and gas from kerogen-containing rocks.
Near-surface oil shales have been mined and retorted at the surface for over a century. In 1862, James Young began processing Scottish oil shales, and that industry lasted for about 100 years. Commercial oil shale retorting has also been conducted in other countries such as Australia, Brazil, China, Estonia, France, Russia, South Africa, Spain, and Sweden. However, the practice has been mostly discontinued in recent years because it proved to be uneconomic or because of environmental constraints on spent shale disposal (REF. 26). Further, surface retorting requires mining of the oil shale, which limits application to shallow formations.
Techniques for in situ retorting of oil shale were developed and pilot tested with the Green River oil shale in the United States. In situ processing offers advantages because it reduces costs associated with material handling and disposal of spent shale. For the in situ pilots, the oil shale was first rubblized and then combustion was carried out by air injection. A rubble bed with substantially uniform fragment size and substantially uniform distribution of void volume was a key success factor in combustion sweep efficiency. Fragment size was of the order of several inches.
Two modified in situ pilots were performed by Occidental and Rio Blanco (REF. 1; REF. 21). A portion of the oil shale was mined out to create a void volume, and then the remaining oil shale was rubblized with explosives. Air was injected at the top of the rubble chamber, the oil shale was ignited, and the combustion front moved down. Retorted oil ahead of the front drained to the bottom and was collected there.
In another pilot, the “true” in situ GEOKINETICS process produced a rubblized volume with carefully designed explosive placement that lifted a 12-meter overburden (REF. 23). Air was injected via wellbores at one end of the rubblized volume, and the combustion front moved horizontally. The oil shale was retorted ahead of the burn; oil drained to the bottom of the rubblized volume and to production wells at one end.
Results from these in situ combustion pilots indicated technical success, but the methods were not commercialized because they were deemed uneconomic. Oil shale rubblization and air compression were the primary cost drivers.
A few authors and inventors have proposed in situ combustion in fractured oil shales, but field tests, where performed, indicated a limited reach from the wellbore (REF. 10; REF. 11; REF. 17).
An in situ retort by thermal conduction from heated wellbores approach was invented by Ljungstrom in 1940 and pioneered by the Swedish Shale Oil Co. with a full scale plant that operated from 1944 into the 1950's (REF. 19; REF. 24). The process was applied to a permeable oil shale at depths of 6 to 24 m near Norrtorp, Sweden. The field was developed with hexagonal patterns, with six heater wells surrounding each vapor production well. Wells were 2.2 m apart. Electrical resistance heaters in wellbores provided heat for a period of five months, which raised the temperature at the production wells to about 400° C. Hydrocarbon vapor production began when the temperature reached 280° C. and continued beyond the heating period. The vapors condensed to a light oil product having a specific gravity of 0.87.
Van Meurs and others further developed the approach of conductive heating from wellbores (REF. 24). They patented a process to apply the approach to impermeable oil shales with heater wells at 600° C. and well spacings greater than 6 m. They propose that the heat-injection wells may be heated either by electrical resistance heaters or by gas-fired combustion heaters. The inventors performed field tests in an outcropping oil shale formation with wells 6 to 12 m deep and 0.6 m apart. After three months, temperatures reached 300° C. throughout the test area. Oil yields were 90% of Fischer Assay. The inventors observed that permeability increased between the wellbores, and they suggest that it may be a result of horizontal fractures formed by the volume expansion of the kerogen to hydrocarbon reaction.
Because conductive heating is limited to distances of several meters, conductive heating from wellbores must be developed with very closely spaced wells. This limits economic application of the process to very shallow oil shales (low well costs) and/or very thick oil shales (higher yield per well).
Covell and others proposed retorting a rubblized bed of oil shale by gasification and combustion of an underlying coal seam (REF. 5). Their process named Total Resource Energy Extraction (TREE), called for upward convection of hot flue gases (727° C.) from the coal seam into the rubblized oil shale bed. Models predicted an operating time of 20 days, and an estimated oil yield of 89% of Fischer Assay. Large-scale experiments with injection of hot flue gases into beds of oil shale blocks showed considerable coking and cracking, which reduced oil recovery to 68% of Fischer Assay. As with the in situ oil shale retorts, the oil shale rubblization involved in this process limits it to shallow oil shales and is expensive.
Passey et al. describe a process to produce hydrocarbons from organic-rich rocks by carrying out in situ combustion of oil in an adjacent reservoir (REF. 16). The organic-rich rock is heated by thermal conduction from the high temperatures achieved in the adjacent reservoir. Upon heating to temperatures in excess of 250° C., the kerogen in the organic-rich rocks is transformed to oil and gas, which are then produced. The permeability of the organic-rich rock increases as a result of the kerogen transformation. This process is limited to organic-rich rocks that have an oil reservoir in an adjacent formation.
In an in situ retort by electromagnetic heating of the formation, electromagnetic energy passes through the formation, and the rock is heated by electrical resistance or by the absorption of dielectric energy. To our knowledge it has not been applied to oil shale, but field tests have been performed in heavy oil formations.
The technical capability of resistive heating within a subterranean formation has been demonstrated in a heavy-oil pilot test where “electric preheat” was used to flow electric current between two wells to lower viscosity and create communication channels between wells for follow-up with a steam flood (REF. 4). Resistive heating within a subterranean formation has been patented and applied commercially by running alternating current or radio frequency electrical energy between stacked conductive fractures or electrodes in the same well (REF. 14; REF. 6; REF. 15; REF. 12). REF. 7 includes a description of resistive heating within a subterranean formation by running alternating current between different wells. Others have described methods to create an effective electrode in a wellbore (REF. 20; REF. 8). REF. 27 describes a method by which electric current is flowed through a fracture connecting two wells to get electric flow started in the bulk of the surrounding formation; heating of the formation occurs primarily due to the bulk electrical resistance of the formation.
Resistive heating of the formation with low-frequency electromagnetic excitation is limited to temperatures below the in situ boiling point of water to maintain the current-carrying capacity of the rock. Therefore, it is not applicable to kerogen conversion where much higher temperatures are required for conversion on production timeframes.
High-frequency heating (radio or microwave frequency) offers the capability to bridge dry rock, so it may be used to heat to higher temperatures. A small-scale field experiment confirmed that high temperatures and kerogen conversion could be achieved (REF. 2). Penetration is limited to a few meters (REF. 25), so this process would require many wellbores and is unlikely to yield economic success.
In these methods that utilize an electrode to deliver electrical excitation directly to the formation, electrical energy passes through the formation and is converted to heat. One patent proposes thermal heating of a gas hydrate from an electrically conductive fracture proppant in only one well, with current flowing into the fracture and presumably to ground (REF. 9).
Even in view of currently available and proposed technologies, it would be advantageous to have improved methods of treating subterranean formations to convert organic matter into producible hydrocarbons.
Therefore, an object of this invention is to provide such improved methods. Other objects of this invention will be made apparent by the following description of the invention.